Methods for treating a subterranean formation with a curable composition using a jetting tool

ABSTRACT

A method of treating a subterranean formation is provided, the method comprising the steps of: positioning a jetting tool in a wellbore penetrating the subterranean formation, wherein the jetting tool comprises at least one fluid jet forming nozzle; and delivering a curable composition through the jetting tool and to the formation, wherein the curable composition: cures to form a solid substance or a semi-solid, gel-like substance, and is a fluid having a sufficiently low viscosity to penetrate into the formation. The methods according to the invention are particularly suited for treating weakly consolidated or unconsolidated formations with a hardenable resin composition to help consolidate the formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

TECHNICAL FIELD

This invention relates generally to improvements in methods that areused to stimulate hydrocarbon (e.g., oil & gas) production from asubterranean formation penetrated by a wellbore. More particularly, thisinvention relates to methods of treating a subterranean formation usinga jetting tool.

BACKGROUND

U.S. Pat. No. 5,249,628 issued Oct. 5, 1993, having for named inventorJim B. Surjaatmadja, and filed on Sep. 29, 1992 discloses casing slipjoints provided on opposite sides of a fracture initiation location toaccommodate casing and formation movement during fracturing of a well.In another aspect of the invention, the fracture initiation location isprovided by forming openings through the well casing and then formingfan-shaped slots in the formation surrounding the casing. Those slotsare formed by a hydraulic jet which is directed through the opening andthen pivoted generally about the point of the opening. These fan-shapedslots circumscribe an angle about the axis of the casing substantiallygreater than the angle circumscribed by the opening itself through whichthe slot was formed. These techniques are particularly applicable tofracturing of horizontal wells. See U.S. Pat. No. 5,249,628, Abstract.The entirety of U.S. Pat. No. 5,249,628 is incorporated herein byreference.

U.S. Pat. No. 5,361,856 issued Nov. 8, 1994, having for named inventorsJim B. Surjaatmadja, Steven L. Holden, and David D. Szarka, and filed onSep. 9, 1993, discloses a well jetting apparatus for use in fracturingof a well. Fracture initiation is provided by forming openings throughthe well casing and then forming fan-shaped slots in the formationsurrounding the casing. Those slots are formed by the jetting apparatuswhich has at least one hydraulic jet directed through the opening. Theapparatus may be pivoted generally about the point of the opening toform the slots, but preferably a plurality of slots are formedsubstantially simultaneously. These fan-shaped slots circumscribe anangle about the axis of the casing substantially greater than the anglecircumscribed by the opening itself through which the slot was formed.These techniques are particularly applicable to fracturing of horizontalwells, but the apparatus may be used in any well configuration. See U.S.Pat. No. 5,361,856, Abstract. The entirety of U.S. Pat. No. 5,361,856 isincorporated herein by reference.

U.S. Pat. No. 5,765,642 issued Jun. 16, 1998, having for named inventorJim B. Surjaatmadja, and filed on Dec. 23, 1996 discloses methods offracturing a subterranean formation, which basically comprisepositioning a hydrajetting tool having at least one fluid jet formingnozzle in the well bore adjacent the formation to be fractured andjetting fluid through the nozzle against the formation at a pressuresufficient to form a fracture in the formation. See U.S. Pat. No.5,765,642, Abstract. The entirety of U.S. Pat. No. 5,765,642 isincorporated herein by reference.

U.S. Pat. No. 6,776,236 issued Aug. 17, 2004, having for named inventorPhillip D. Nguyen, and filed on Oct. 16, 2002, discloses methods ofcompleting unconsolidated hydrocarbon producing zones penetrated bycased and cemented well bores. The methods include the steps of formingspaced openings through the casing and cement and injecting a firsthardenable resin composition through the openings into theunconsolidated producing zone adjacent to the well bore. Without waitingfor the first hardenable resin composition to harden, a fracturing fluidcontaining proppant particles coated with a second hardenable resincomposition is injected through the openings into the unconsolidatedproducing zone at a rate and pressure sufficient to fracture theproducing zone. The proppant particles coated with the second hardenableresin composition are deposited in the fractures and the first andsecond hardenable resin compositions are allowed to harden by heat. SeeU.S. Pat. No. 6,776,236, Abstract. The entirety of U.S. Pat. No.6,776,236 is incorporated herein by reference.

SUMMARY OF THE INVENTION

According to the invention, a method of treating a subterraneanformation, is provided, the method comprising the steps of: positioninga jetting tool in a wellbore penetrating the subterranean formation,wherein the jetting tool comprises at least one fluid jet formingnozzle; and delivering a curable composition through the jetting tooland to the formation, wherein at least a component of the curablecomposition is capable of curing to form a solid substance or asemi-solid, gel-like substance, and the curable composition is a fluidhaving a sufficiently low viscosity to penetrate into the formation.

According to another aspect of the invention, a method of treating asubterranean formation is provided, the method comprising the steps of:isolating an interval of the wellbore penetrating the subterraneanformation; positioning a jetting tool in the isolated interval of thesubterranean formation, wherein the jetting tool comprises at least onefluid jet forming nozzle; injecting a fracturing fluid through thejetting tool under conditions sufficient to erode a portion of the wallof the well bore and to initiate at least one fracture extending intothe formation; and delivering a curable composition through the jettingtool and to the formation, wherein at least a component of the curablecomposition is capable of curing to form a solid substance or asemi-solid, gel-like substance, and the curable composition is a fluidhaving a sufficiently low viscosity to penetrate into the formation.

According to yet another aspect of the invention, a method of treating asubterranean formation is provided, wherein the formation is weaklyconsolidated or unconsolidated, the method comprising the steps of:positioning a jetting tool a wellbore penetrating the subterraneanformation, wherein the jetting tool comprises at least one fluid jetforming nozzle; injecting a fracturing fluid through the jetting toolunder conditions sufficient to erode a portion of the wall of the wellbore and to initiate at least one fracture extending into the formation;and delivering a curable composition through the jetting tool and to theformation, wherein at least a component of the curable composition iscapable of curing to form a solid substance or a semi-solid, gel-likesubstance, and the curable composition is a fluid having a sufficientlylow viscosity to penetrate into the formation.

Therefore, from the foregoing, it is a general object of the presentinvention to provide improved methods for treating a formation includingthe use of a jetting tool and for delivering a curable compositionthrough the jetting tool. Other and further objects, features andadvantages of the present invention will be readily apparent to thoseskilled in the art when the following description of the preferredembodiments is read in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a schematic diagram illustrating a jetting tool creatingperforation tunnels through an uncased horizontal wellbore in a firstzone of a subterranean formation.

FIG. 1B is a schematic diagram illustrating a jetting tool creatingperforation tunnels through a cased horizontal wellbore in a first zoneof a subterranean formation.

FIG. 2 is a schematic diagram illustrating a cross-sectional view of thejetting tool shown in FIG. 1 forming four equally spaced perforationtunnels in the first zone of the subterranean formation.

FIG. 3 is a schematic diagram illustrating the creation of fractures inthe first zone by the jetting tool wherein the plane of the fracture(s)is perpendicular to the wellbore axis.

FIGS. 4A and 4B illustrate operation of a jetting tool for use incarrying out the methods according to the present invention.

DETAILED DESCRIPTION

As used herein and in the appended claims, the words “comprise,” “has,”and “include” and all grammatical variations thereof are each intendedto have an open, non-limiting meaning that does not exclude additionalelements or parts of an assembly, subassembly, or structural element.

If there is any conflict in the usages of a word or term in thisspecification and one or more patent or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

In general, the invention according to the present invention provides amethod of treating a subterranean formation, the method comprising thesteps of: positioning a jetting tool in a wellbore penetrating thesubterranean formation, wherein the jetting tool comprises at least onefluid jet forming nozzle; and delivering a curable composition throughthe jetting tool and to the formation, wherein at least a component ofthe curable composition is capable of curing to form a solid substanceor a semi-solid, gel-like substance, and the curable composition is afluid having a sufficiently low viscosity to penetrate into theformation. The low viscosity fluid can be obtained by thinning downhigher viscosity fluids using solvents.

Preferably, the viscosity is sufficiently low that no substantial amountof residue remains behind filling the pore spaces of the formation asthe curable composition penetrates into the formation. This allows theplacement of the curable composition to be better controlled and withoutundesired effects on the permeability of the formation.

The low-viscosity curable composition is capable of penetrating thesubterranean formation at relatively low flow rate and pressuredifferential. For example, the delivery rate through the jetting tooland to the formation would typically be less than about 2 barrels perminute.

Even when the method is used to treat a proppant pack in a fracture in asubterranean formation or a gravel pack adjacent the formation, thecurable composition should have a sufficiently low viscosity topenetrate into the formation. This avoids risking any substantialplugging of the permeability of the surrounding formation.

Regardless of the type of curable composition chosen for use in treatinga subterranean formation, the viscosity of the curable compositionshould be sufficiently low to be able to penetrate into the subterraneanformation. For example, for a weakly consolidated or unconsolidatedformation, the viscosity should be sufficient low to penetrate into therock of the formation.

To achieve the desired penetration, the apparent viscosity of thecurable composition is preferably below about 100 centipoise (“cP”),more preferably below about 50 cP, and most preferably below about 10cP. The apparent viscosity is preferably measured within the range ofthe bottom hole static temperature (“BHST”) of the subterraneanformation. More preferably, the apparent viscosity of the curablecomposition is measured at the lower limit of the bottom hole statictemperature of the subterranean formation. Achieving the desiredviscosity will generally involve either the use of a solvent, althoughthe use of heat can be used to reduce the viscosity of the chosencurable composition.

Factors that may influence the amount of solvent needed include thegeographic location of the well and the surrounding environmentalconditions. In some embodiments, suitable consolidating fluid-to-solventratios range from about 1:0.2 to about 1:20. It is within the ability ofone skilled in the art, with the benefit of this disclosure, todetermine a sufficient amount of a suitable solvent to achieve thedesired viscosity and, thus, to achieve the preferred penetration intothe subterranean formation. Placement or mixing of the solvents can bedone uphole (on surface) or can be performed in situ (downhole). Thiscan be achieved by taking advantage of the annular passages, or a secondtubular system downhole.

The method is particularly useful where the formation is a weaklyconsolidated or unconsolidated formation. In such a situation, thecurable composition is preferably a hardenable resin composition.

For consolidation applications, in which case the curable compositionsare sometimes referred to as consolidation fluids, suitable resinsinclude all resins know in the art that are capable of forming ahardened, consolidated mass. Many such resins are commonly used insubterranean consolidation operations, and some suitable resins includetwo component epoxy based resins, novolak resins, polyepoxide resins,phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolicresins, furan resins, furan/furfuryl alcohol resins, phenolic/latexresins, phenol formaldehyde resins, polyester resins and hybrids andcopolymers thereof, polyurethane resins and hybrids and copolymersthereof, acrylate resins, and mixtures thereof. Some suitable resins,such as epoxy resins, may be cured with an internal catalyst oractivator so that when pumped down hole, they may be cured using onlytime and temperature. Other suitable resins, such as furan resinsgenerally require a time-delayed catalyst or an external catalyst tohelp activate the polymerization of the resins if the cure temperatureis low (i.e., less than 250° F.), but will cure under the effect of timeand temperature if the formation temperature is above about 250° F.,preferably above about 300° F. It is within the ability of one skilledin the art, with the benefit of this disclosure, to select a suitableresin for use in embodiments of the present invention and to determinewhether a catalyst is required to trigger curing. Again, this does notpreclude the ability of mixing the catalysts downhole when so desired.

Selection of a suitable resin may be affected by the temperature of thesubterranean formation to which the fluid will be introduced. By way ofexample, for subterranean formations having a bottom hole statictemperature (“BHST”) ranging from about 60° F. to about 250° F.,two-component epoxy-based resins comprising a hardenable resin componentand a hardening agent component containing specific hardening agents maybe preferred. For subterranean formations having a BHST ranging fromabout 300° F. to about 600° F., a furan-based resin may be preferred.For subterranean formations having a BHST ranging from about 200° F. toabout 400° F., either a phenolic-based resin or a one-component HTepoxy-based resin may be suitable. For subterranean formations having aBHST of at least about 175° F., a phenol/phenol formaldehyde/furfurylalcohol resin may also be suitable.

Any solvent that is compatible with the chosen resin and achieves thedesired viscosity effect is suitable for use in the present invention.Some preferred solvents are those having high flash points (e.g., about125° F.) because of, among other things, environmental and safetyconcerns; such solvents include butyl lactate, butylglycidyl ether,dipropylene glycol methyl ether, dipropylene glycol dimethyl ether,dimethyl formanide, diethyleneglycol methyl ether, ethyleneglycol butylether, diethyleneglycol butyl ether, propylene carbonate, methanol,butyl alcohol, d'limonene, fatty acid methyl esters, and combinationsthereof. Other preferred solvents include aqueous dissolvable solventssuch as, methanol, isopropanol, butanol, glycol ether solvents, andcombinations thereof. Suitable glycol ether solvents include, but arenot limited to, diethylene glycol methyl ether, dipropylene glycolmethyl ether, 2-butoxy ethanol, ethers of a C₂ to C₆ dihydric alkanolcontaining at least one C₁ to C₆ alkyl group, mono ethers of dihydricalkanols, methoxypropanol, butoxyethanol, hexoxyethanol, and isomersthereof. Selection of an appropriate solvent is dependent on the resinchosen and is within the ability of one skilled in the art with thebenefit of this disclosure.

One resin-type coating material suitable for use in the methods of thepresent invention is a two-component epoxy based resin comprising ahardenable resin component and a hardening agent component. Thehardenable resin component is comprised of a hardenable resin and anoptional solvent. The solvent may be added to the resin to reduce itsviscosity for ease of handling, mixing and transferring. It is withinthe ability of one skilled in the art with the benefit of thisdisclosure to determine if and how much solvent may be needed to achievea viscosity suitable to the subterranean conditions. Factors that mayaffect this decision include geographic location of the well and thesurrounding weather conditions. An alternate way to reduce the viscosityof the liquid hardenable resin is to heat it. This method avoids the useof a solvent altogether, which may be desirable in certaincircumstances. The second component is the liquid hardening agentcomponent, which is comprised of a hardening agent, a silane couplingagent, a surfactant, an optional hydrolyzable ester for, among otherthings, breaking gelled fracturing fluid films on the proppantparticles, and an optional liquid carrier fluid for, among other things,reducing the viscosity of the liquid hardening agent component. It iswithin the ability of one skilled in the art with the benefit of thisdisclosure to determine if and how much liquid carrier fluid is neededto achieve a viscosity suitable to the subterranean conditions.

Examples of hardenable resins that can be used in the hardenable resincomponent include, but are not limited to, organic resins such asbisphenol A diglycidyl ether resin, butoxymethyl butyl glycidyl etherresin, bisphenol A-epichlorohydrin resin, polyepoxide resin, novolakresin, polyester resin, phenol-aldehyde resin, urea-aldehyde resin,furan resin, urethane resin, a glycidyl ether resin, and combinationsthereof. The hardenable resin used is included in the hardenable resincomponent in an amount in the range of from about 60% to about 100% byweight of the hardenable resin component. In some embodiments thehardenable resin used is included in the hardenable resin component inan amount of about 70% to about 90% by weight of the hardenable resincomponent.

Any solvent that is compatible with the hardenable resin and achievesthe desired viscosity effect is suitable for use in the hardenable resincomponent of the integrated consolidation fluids of the presentinvention. Some preferred solvents are those having high flash points(e.g., about 125° F.) because of, among other things, environmental andsafety concerns; such solvents include butyl lactate, butylglycidylether, dipropylene glycol methyl ether, dipropylene glycol dimethylether, dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycolbutyl ether, diethyleneglycol butyl ether, propylene carbonate,methanol, butyl alcohol, d'limonene, fatty acid methyl esters, andcombinations thereof. Other preferred solvents include aqueousdissolvable solvents such as, methanol, isopropanol, butanol, glycolether solvents, and combinations thereof. Suitable glycol ether solventsinclude, but are not limited to, diethylene glycol methyl ether,dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C2 to C6dihydric alkanol containing at least one C₁ to C₆ alkyl group, monoethers of dihydric alkanols, methoxypropanol, butoxyethanol,hexoxyethanol, and isomers thereof. Selection of an appropriate solventis dependent on the resin composition chosen and is within the abilityof one skilled in the art with the benefit of this disclosure.

As described above, use of a solvent in the hardenable resin componentis optional but may be desirable to reduce the viscosity of thehardenable resin component for ease of handling, mixing, andtransferring. It is within the ability of one skilled in the art, withthe benefit of this disclosure, to determine if and how much solvent isneeded to achieve a suitable viscosity. In some embodiments the amountof the solvent used in the hardenable resin component is in the range offrom about 0.1% to about 30% by weight of the hardenable resincomponent. Optionally, the hardenable resin component may be heated toreduce its viscosity, in place of, or in addition to, using a solvent.

Examples of the hardening agents that can be used in the liquidhardening agent component of the two-component consolidation fluids ofthe present invention include, but are not limited to, piperazine,derivatives of piperazine (e.g., aminoethylpiperazine), 2H-pyrrole,pyrrole, imidazole, pyrazole, pyridine, pyrazine, pyrimidine,pyridazine, indolizine, isoindole, 3H-indole, indole, 1H-indazole,purine, 4H-quinolizine, quinoline, isoquinoline, phthalazine,naphthyridine, quinoxaline, quinazoline, 4H-carbazole, carbazole,β-carboline, phenanthridine, acridine, phenathroline, phenazine,imidazolidine, phenoxazine, cinnoline, pyrrolidine, pyrroline,imidazoline, piperidine, indoline, isoindoline, quinuclindine,morpholine, azocine, azepine, 2H-azepine, 1,3,5-triazine, thiazole,pteridine, dihydroquinoline, hexa methylene imine, indazole, amines,aromatic amines, polyamines, aliphatic amines, cyclo-aliphatic amines,amides, polyamides, 2-ethyl-4-methyl imidazole,1,1,3-trichlorotrifluoroacetone, and combinations thereof. The chosenhardening agent often effects the range of temperatures over which ahardenable resin is able to cure. By way of example and not oflimitation, in subterranean formations having a temperature from about60° F. to about 250° F., amines and cyclo-aliphatic amines such aspiperidine, triethylamine, N,N-dimethylaminopyridine,benzyldimethylamine, tris(dimethylaminomethyl) phenol, and2-(N2N-dimethylaminomethyl)phenol are preferred withN,N-dimethylaminopyridine most preferred. In subterranean formationshaving higher temperatures, 4,4′-diaminodiphenyl sulfone may be asuitable hardening agent. Hardening agents that comprise piperazine or aderivative of piperazine have been shown capable of curing varioushardenable resins from temperatures as low as about 70° F. to as high asabout 350° F. The hardening agent used is included in the liquidhardening agent component in an amount sufficient to consolidate thecoated particulates. In some embodiments of the present invention, thehardening agent used is included in the liquid hardenable resincomponent in the range of from about 40% to about 60% by weight of theliquid hardening agent component. In some embodiments the hardenableresin used is included in the hardenable resin component in an amount ofabout 45% to about 55% by weight of the liquid hardening agentcomponent.

The silane coupling agent may be used, among other things, to act as amediator to help bond the resin to formation particulates and-orproppant. Examples of suitable silane coupling agents include, but arenot limited to, N-β-(aminoethyl)-γ-aminopropyl trimethoxysilane,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane,3-glycidoxypropyltrimethoxysilane, and combinations thereof. The silanecoupling agent used is included in the liquid hardening agent componentin an amount capable of sufficiently bonding the resin to theparticulate. In some embodiments of the present invention, the silanecoupling agent used is included in the liquid hardenable resin componentin the range of from about 0.1% to about 3% by weight of the liquidhardening agent component.

Any surfactant compatible with the hardening agent and capable offacilitating the coating of the resin onto particles in the subterraneanformation may be used in the hardening agent component of the integratedconsolidation fluids of the present invention. Such surfactants include,but are not limited to, an alkyl phosphonate surfactant (e.g., a Cl₂-C₂₂alkyl phosphonate surfactant), an ethoxylated nonyl phenol phosphateester, one or more cationic surfactants, and one or more nonionicsurfactants. Mixtures of one or more cationic and nonionic surfactantsalso may be suitable. Examples of such surfactant mixtures are describedin U.S. Pat. No. 6,311,773 issued to Todd et al. on Nov. 6, 2001, therelevant disclosure of which is incorporated herein by reference. Thesurfactant or surfactants used are included in the liquid hardeningagent component in an amount in the range of from about 1% to about 10%by weight of the liquid hardening agent component.

While not required, examples of hydrolysable esters that can be used inthe hardening agent component of the integrated consolidation fluids ofthe present invention include, but are not limited to, a mixture ofdimethylglutarate, dimethyladipate, and dimethylsuccinate; sorbitol;catechol; dimethylthiolate; methyl salicylate; dimethyl salicylate;dimethylsuccinate; ter-butylhydroperoxide; and combinations thereof.When used, a hydrolyzable ester is included in the hardening agentcomponent in an amount in the range of from about 0.1% to about 3% byweight of the hardening agent component. In some embodiments ahydrolysable ester is included in the hardening agent component in anamount in the range of from about 1% to about 2.5% by weight of thehardening agent component.

Use of a diluent or liquid carrier fluid in the hardenable resincomposition is optional and may be used to reduce the viscosity of thehardenable resin component for ease of handling, mixing andtransferring. It is within the ability of one skilled in the art, withthe benefit of this disclosure, to determine if and how much liquidcarrier fluid is needed to achieve a viscosity suitable to thesubterranean conditions. Any suitable carrier fluid that is compatiblewith the hardenable resin and achieves the desired viscosity effects issuitable for use in the present invention. Some preferred liquid carrierfluids are those having high flash points (e.g., about 125° F.) becauseof, among other things, environmental and safety concerns; such solventsinclude butyl lactate, butylglycidyl ether, dipropylene glycol methylether, dipropylene glycol dimethyl ether, dimethyl formamide,diethyleneglycol methyl ether, ethyleneglycol butyl ether,diethyleneglycol butyl ether, propylene carbonate, methanol, butylalcohol, d'limonene, fatty acid methyl esters, and combinations thereof.Other preferred liquid carrier fluids include aqueous dissolvablesolvents such as, methanol, isopropanol, butanol, glycol ether solvents,and combinations thereof. Suitable glycol ether liquid carrier fluidsinclude, but are not limited to, diethylene glycol methyl ether,dipropylene glycol methyl ether, 2-butoxy ethanol, ethers of a C₂ to C₆dihydric alkanol containing at least one C₁ to C₆ alkyl group, monoethers of dihydric alkanols, methoxypropanol, butoxyethanol,hexoxyethanol, and isomers thereof. Selection of an appropriate liquidcarrier fluid is dependent on the resin composition chosen and is withinthe ability of one skilled in the art with the benefit of thisdisclosure.

Another type of resin suitable for use in the methods of the presentinvention is a furan-based resin. Suitable furan-based resins include,but are not limited to, furfuryl alcohol resins, mixtures furfurylalcohol resins and aldehydes, and a mixture of furan resins and phenolicresins. Of these, furfuryl alcohol resins are preferred. A furan-basedresin may be combined with a solvent to control viscosity if desired.Suitable solvents for use in the furan-based consolidation fluids of thepresent invention include, but are not limited to 2-butoxy ethanol,butyl lactate, butyl acetate, tetrahydrofurfuryl methacrylate,tetrahydrofurfuryl acrylate, esters of oxalic, maleic and succinicacids,and furfuryl acetate. Of these, 2-butoxy ethanol is preferred.

Still another type of resin suitable for use in the methods of thepresent invention is a phenolic-based resin. Suitable phenolic-basedresins include, but are not limited to, terpolymers of phenol, phenolicformaldehyde resins, and a mixture of phenolic and furan resins. Ofthese, a mixture of phenolic and furan resins is preferred. Aphenolic-based resin may be combined with a solvent to control viscosityif desired. Suitable solvents for use in the phenolic-basedconsolidation fluids of the present invention include, but are notlimited to butyl acetate, butyl lactate, furfuryl acetate, and 2-butoxyethanol. Of these, 2-butoxy ethanol is preferred.

Another type of resin suitable for use in the methods of the presentinvention is a HT epoxy-based resin. Suitable HT epoxy-based componentsinclude, but are not limited to, bisphenol A-epichlorohydrin resins,polyepoxide resins, novolac resins, polyester resins, glycidyl ethersand mixtures thereof. Of these, bisphenol A-epichlorohydrin resins arepreferred. An HT epoxy-based resin may be combined with a solvent tocontrol viscosity if desired. Suitable solvents for use with the HTepoxy-based resins of the present invention are those solvents capableof substantially dissolving the HT epoxy-resin chosen for use in theconsolidation fluid. Such solvents include, but are not limited to,dimethyl sulfoxide and dimethyl formamide. A co-solvent such as adipropylene glycol methyl ether, dipropylene glycol dimethyl ether,dimethyl formamide, diethylene glycol methyl ether, ethylene glycolbutyl ether, diethylene glycol butyl ether, propylene carbonate,d'limonene and fatty acid methyl esters, may also be used in combinationwith the solvent.

Yet another resin-type coating material suitable for use in the methodsof the present invention is a phenol/phenol formaldehyde/furfurylalcohol resin comprising from about 5% to about 30% phenol, from about40% to about 70% phenol formaldehyde, from about 10 to about 40%furfuryl alcohol, from about 0.1% to about 3% of a silane couplingagent, and from about 1% to about 15% of a surfactant. In thephenol/phenol formaldehyde/furfuryl alcohol resins suitable for use inthe methods of the present invention, suitable silane coupling agentsinclude, but are not limited to,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane,3-glycidoxypropyltrimethoxysilane, andn-beta-(aminoethyl)-gamma-aminopropyl trimethoxysilane. Suitablesurfactants include, but are not limited to, an ethoxylated nonyl phenolphosphate ester, mixtures of one or more cationic surfactants, and oneor more non-ionic surfactants and an alkyl phosphonate surfactant.

Gelable compositions suitable for use in the present invention includethose compositions that cure to form a semi-solid, gel-like substance.The gelable composition may be any gelable liquid composition capable ofconverting into a gelled substance capable of substantiallyconsolidating the formation while allowing the formation to remainflexible. As referred to herein, the term “flexible” refers to a statewherein the treated portion of the formation is relatively malleable andelastic and able to withstand substantial pressure cycling withoutsubstantial breakdown of the formation. Thus, the resultant gelledsubstance stabilizes the treated portion of the formation while allowingthe formation to absorb the stresses created during pressure cycling. Asa result, the gelled substance may aid in preventing breakdown of theformation both by stabilizing and by adding flexibility to the treatedportion. Examples of suitable gelable liquid compositions include, butare not limited to, (1) gelable resin compositions, (2) gelable aqueoussilicate compositions, (3) crosslinkable aqueous polymer compositions,and (4) polymerizable organic monomer compositions.

Certain embodiments of the gelable liquid compositions of the presentinvention comprise gelable resin compositions that cure to form flexiblegels. Unlike the hardenable resin compositions described above, whichcure into hardened masses, the gelable resin compositions cure intoflexible, gelled substances that form resilient gelled substancesbetween the particulates of the treated zone of the unconsolidatedformation. Gelable resin compositions allow the treated portion of theformation to remain flexible and resist breakdown.

Generally, the gelable resin compositions useful in accordance with thisinvention comprise a curable resin, a diluent, and a resin curing agent.When certain resin curing agents, such as polyamides, are used in thecurable resin compositions, the compositions form the semi-solid, gelledsubstances described above. Where the resin curing agent used may causethe organic resin compositions to form hard, brittle material ratherthan a desired gelled substance, the curable resin compositions mayfurther comprise one or more “flexibilizer additives” (described in moredetail below) to provide flexibility to the cured compositions.

Examples of gelable resins that can be used in the present inventioninclude, but are not limited to, organic resins such as polyepoxideresins (e.g., Bisphenol a-epichlorihydrin resins), polyester resins,urea-aldehyde resins, furan resins, urethane resins, and mixturesthereof. Of these, polyepoxide resins are preferred.

Any diluent that is compatible with the gelable resin and achieves thedesired viscosity effect is suitable for use in the present invention.Examples of diluents that may be used in the gelable resin compositionsof the present invention include, but are not limited to, phenols;formaldehydes; furfuryl alcohols; furfurals; alcohols; ethers such asbutyl glycidyl ether and cresyl glycidyl etherphenyl glycidyl ether; andmixtures thereof. In some embodiments of the present invention, thediluent comprises butyl lactate. The diluent may be used to reduce theviscosity of the gelable resin composition. Among other things, thediluent acts to provide flexibility to the cured composition. Thediluent may be included in the gelable resin composition in an amountsufficient to provide the desired viscosity effect. Subject to providingthe desired viscosity effect, generally, the diluent used is included inthe gelable resin composition in amount in the range of from about 5% toabout 75% by weight of the curable resin.

Generally, any resin curing agent that may be used to cure an organicresin is suitable for use in the present invention. When the resincuring agent chosen is an amide or a polyamide, generally noflexibilizer additive will be required because, among other things, suchcuring agents cause the gelable resin composition to convert into asemi-solid, gelled substance. Other suitable resin curing agents (suchas an amine, a polyamine, methylene dianiline, and other curing agentsknown in the art) will tend to cure into a hard, brittle material andwill thus benefit from the addition of a flexibilizer additive.Generally, the resin curing agent used is included in the gelable resincomposition, whether a flexibilizer additive is included or not, in anamount in the range of from about 5% to about 75% by weight of thecurable resin. In some embodiments of the present invention, the resincuring agent used is included in the gelable resin composition in anamount in the range of from about 20% to about 75% by weight of thecurable resin.

As noted above, flexibilizer additives may be used, among other things,to provide flexibility to the gelled substances formed from the curableresin compositions. Flexibilizer additives may be used where the resincuring agent chosen would cause the gelable resin composition to cureinto a hard and brittle material—rather than a desired gelled substance.For example, flexibilizer additives may be used where the resin curingagent chosen is not an amide or polyamide. Examples of suitableflexibilizer additives include, but are not limited to, an organicester, an oxygenated organic solvent, an aromatic solvent, andcombinations thereof. Of these, ethers, such as dibutyl phthalate, arepreferred. Where used, the flexibilizer additive may be included in thegelable resin composition in an amount in the range of from about 5% toabout 80% by weight of the gelable resin. In some embodiments of thepresent invention, the flexibilizer additive may be included in thecurable resin composition in an amount in the range of from about 20% toabout 45% by weight of the curable resin.

In other embodiments, the gelable liquid compositions of the presentinvention may comprise a gelable aqueous silicate composition.Generally, the gelable aqueous silicate compositions that are useful inaccordance with the present invention generally comprise an aqueousalkali metal silicate solution and a temperature activated catalyst forgelling the aqueous alkali metal silicate solution.

The aqueous alkali metal silicate solution component of the gelableaqueous silicate compositions generally comprise an aqueous liquid andan alkali metal silicate. The aqueous liquid component of the aqueousalkali metal silicate solution generally may be fresh water, salt water(e.g., water containing one or more salts dissolved therein), brine(e.g., saturated salt water), seawater, or any other aqueous liquid thatdoes not adversely react with the other components used in accordancewith this invention or with the subterranean formation. Examples ofsuitable alkali metal silicates include, but are not limited to, one ormore of sodium silicate, potassium silicate, lithium silicate, rubidiumsilicate, or cesium silicate. Of these, sodium silicate is preferred.While sodium silicate exists in many forms, the sodium silicate used inthe aqueous alkali metal silicate solution preferably has a Na₂O-to-SiO₂weight ratio in the range of from about 1:2 to about 1:4. Mostpreferably, the sodium silicate used has a Na₂O-to-SiO₂ weight ratio inthe range of about 1:3.2. Generally, the alkali metal silicate ispresent in the aqueous alkali metal silicate solution component in anamount in the range of from about 0.1% to about 10% by weight of theaqueous alkali metal silicate solution component.

The temperature-activated catalyst component of the gelable aqueoussilicate compositions is used, among other things, to convert thegelable aqueous silicate compositions into the desired semi-solid,gel-like substance described above. Selection of a temperature-activatedcatalyst is related, at least in part, to the temperature of thesubterranean formation to which the gelable aqueous silicate compositionwill be introduced. The temperature-activated catalysts that can be usedin the gelable aqueous silicate compositions of the present inventioninclude, but are not limited to, ammonium sulfate (which is mostsuitable in the range of from about 60° F. to about 240° F.); sodiumacid pyrophosphate (which is most suitable in the range of from about60° F. to about 240° F.); citric acid (which is most suitable in therange of from about 60° F. to about 120° F.); and ethyl acetate (whichis most suitable in the range of from about 60° F. to about 120° F.).Generally, the temperature-activated catalyst is present in the gelableaqueous silicate composition in the range of from about 0.1% to about 5%by weight of the gelable aqueous silicate composition.

In other embodiments, the gelable liquid compositions of the presentinvention comprise crosslinkable aqueous polymer compositions.Generally, suitable crosslinkable aqueous polymer compositions comprisean aqueous solvent, a crosslinkable polymer, and a crosslinking agent.Such compositions are similar to those used to form gelled treatmentfluids, such as fracturing fluids, but, according to the methods of thepresent invention, they are not exposed to breakers or de-linkers and sothey retain their viscous nature over time.

The aqueous solvent may be any aqueous solvent in which thecrosslinkable composition and the crosslinking agent may be dissolved,mixed, suspended, or dispersed therein to facilitate gel formation. Forexample, the aqueous solvent used may be fresh water, salt water, brine,seawater, or any other aqueous liquid that does not adversely react withthe other components used in accordance with this invention or with thesubterranean formation.

Examples of crosslinkable polymers that can be used in the crosslinkableaqueous polymer compositions include, but are not limited to,carboxylate-containing polymers and acrylamide-containing polymers.Preferred acrylamide-containing polymers include polyacrylamide,partially hydrolyzed polyacrylamide, copolymers of acrylamide andacrylate, and carboxylate-containing terpolymers and tetrapolymers ofacrylate. Additional examples of suitable crosslinkable polymers includehydratable polymers comprising polysaccharides and derivatives thereofand that contain one or more of the monosaccharide units galactose,mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronicacid, or pyranosyl sulfate. Suitable natural hydratable polymersinclude, but are not limited to, guar gum, locust bean gum, tara,konjak, tamarind, starch, cellulose, karaya, xanthan, tragacanth, andcarrageenan, and derivatives of all of the above. Suitable hydratablesynthetic polymers and copolymers that may be used in the crosslinkableaqueous polymer compositions include, but are not limited to,polyacrylates, polymethacrylates, polyacrylamides, maleic anhydride,methylvinyl ether polymers, polyvinyl alcohols, andpolyvinylpyrrolidone. The crosslinkable polymer used should be includedin the crosslinkable aqueous polymer composition in an amount sufficientto form the desired gelled substance in the subterranean formation. Insome embodiments of the present invention, the crosslinkable polymer isincluded in the crosslinkable aqueous polymer composition in an amountin the range of from about 1% to about 30% by weight of the aqueoussolvent. In another embodiment of the present invention, thecrosslinkable polymer is included in the crosslinkable aqueous polymercomposition in an amount in the range of from about 1% to about 20% byweight of the aqueous solvent.

The crosslinkable aqueous polymer compositions of the present inventionfurther comprise a crosslinking agent for crosslinking the crosslinkablepolymers to form the desired gelled substance. In some embodiments, thecrosslinking agent is a molecule or complex containing a reactivetransition metal cation. A most preferred crosslinking agent comprisestrivalent chromium cations complexed or bonded to anions, atomic oxygen,or water. Examples of suitable crosslinking agents include, but are notlimited to, compounds or complexes containing chromic acetate and/orchromic chloride. Other suitable transition metal cations includechromium VI within a redox system, aluminum III, iron II, iron III, andzirconium IV.

The crosslinking agent should be present in the crosslinkable aqueouspolymer compositions of the present invention in an amount sufficient toprovide, among other things, the desired degree of crosslinking. In someembodiments of the present invention, the crosslinking agent is presentin the crosslinkable aqueous polymer compositions of the presentinvention in an amount in the range of from about 0.01% to about 5% byweight of the crosslinkable aqueous polymer composition. The exact typeand amount of crosslinking agent or agents used depends upon thespecific crosslinkable polymer to be crosslinked, formation temperatureconditions, and other factors known to those individuals skilled in theart.

Optionally, the crosslinkable aqueous polymer compositions may furthercomprise a crosslinking delaying agent, such as a polysaccharidecrosslinking delaying agent derived from guar, guar derivatives, orcellulose derivatives. The crosslinking delaying agent may be includedin the crosslinkable aqueous polymer compositions, among other things,to delay crosslinking of the crosslinkable aqueous polymer compositionsuntil desired. One of ordinary skill in the art, with the benefit ofthis disclosure, will know the appropriate amount of the crosslinkingdelaying agent to include in the crosslinkable aqueous polymercompositions for a desired application.

In other embodiments, the gelled liquid compositions of the presentinvention comprise polymerizable organic monomer compositions.Generally, suitable polymerizable organic monomer compositions comprisean aqueous-base fluid, a water-soluble polymerizable organic monomer, anoxygen scavenger, and a primary initiator.

The aqueous-based fluid component of the polymerizable organic monomercomposition generally may be fresh water, salt water, brine, seawater,or any other aqueous liquid that does not adversely react with the othercomponents used in accordance with this invention or with thesubterranean formation.

A variety of monomers are suitable for use as the water-solublepolymerizable organic monomers in the present invention. Examples ofsuitable monomers include, but are not limited to, acrylic acid,methacrylic acid, acrylamide, methacrylamide,2-methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide,vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate,2-triethylammoniumethylmethacrylate chloride,N,N-dimethyl-aminopropylmethacryl-amide,methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone,vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammoniumsulfate, and mixtures thereof. Preferably, the water-solublepolymerizable organic monomer should be self-crosslinking. Examples ofsuitable monomers which are self crosslinking include, but are notlimited to, hydroxyethylacrylate, hydroxymethylacrylate,hydroxyethylmethacrylate, N-hydroxymethylacrylaamide,N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate,polyethylene glycol methacrylate, polypropylene gylcol acrylate,polypropylene glycol methacrylate, and mixtures thereof. Of these,hydroxyethylacrylate is preferred. An example of a particularlypreferable monomer is hydroxyethylcellulose-vinyl phosphoric acid.

The water-soluble polymerizable organic monomer (or monomers where amixture thereof is used) should be included in the polymerizable organicmonomer composition in an amount sufficient to form the desired gelledsubstance after placement of the polymerizable organic monomercomposition into the subterranean formation. In some embodiments of thepresent invention, the water-soluble polymerizable organic monomer isincluded in the polymerizable organic monomer composition in an amountin the range of from about 1% to about 30% by weight of the aqueous-basefluid. In another embodiment of the present invention, the water-solublepolymerizable organic monomer is included in the polymerizable organicmonomer composition in an amount in the range of from about 1% to about20% by weight of the aqueous-base fluid.

The presence of oxygen in the polymerizable organic monomer compositionmay inhibit the polymerization process of the water-solublepolymerizable organic monomer or monomers. Therefore, an oxygenscavenger, such as stannous chloride, may be included in thepolymerizable monomer composition. In order to improve the solubility ofstannous chloride so that it may be readily combined with thepolymerizable organic monomer composition on the fly, the stannouschloride may be pre-dissolved in a hydrochloric acid solution. Forexample, the stannous chloride may be dissolved in a 0.1% by weightaqueous hydrochloric acid solution in an amount of about 10% by weightof the resulting solution. The resulting stannous chloride-hydrochloricacid solution may be included in the polymerizable organic monomercomposition in an amount in the range of from about 0.1% to about 10% byweight of the polymerizable organic monomer composition. Generally, thestannous chloride may be included in the polymerizable organic monomercomposition of the present invention in an amount in the range of fromabout 0.005% to about 0.1% by weight of the polymerizable organicmonomer composition.

The primary initiator is used, among other things, to initiatepolymerization of the water-soluble polymerizable organic monomer(s)used in the present invention. Any compound or compounds that form freeradicals in aqueous solution may be used as the primary initiator. Thefree radicals act, among other things, to initiate polymerization of thewater-soluble polymerizable organic monomer present in the polymerizableorganic monomer composition. Compounds suitable for use as the primaryinitiator include, but are not limited to, alkali metal persulfates;peroxides; oxidation-reduction systems employing reducing agents, suchas sulfites in combination with oxidizers; and azo polymerizationinitiators. Preferred azo polymerization initiators include2,2′-azobis(2-imidazole-2-hydroxyethyl) propane, 2,2′-azobis(2-aminopropane), 4,4′-azobis (4-cyanovaleric acid), and 2,2′-azobis(2-methyl-N-(2-hydroxyethyl) propionamide. Generally, the primaryinitiator should be present in the polymerizable organic monomercomposition in an amount sufficient to initiate polymerization of thewater-soluble polymerizable organic monomer(s). In certain embodimentsof the present invention, the primary initiator is present in thepolymerizable organic monomer composition in an amount in the range offrom about 0.1% to about 5% by weight of the water-soluble polymerizableorganic monomer(s). One skilled in the art will recognize that as thepolymerization temperature increases, the required level of activatordecreases.

Optionally, the polymerizable organic monomer compositions further maycomprise a secondary initiator. A secondary initiator may be used, forexample, where the immature aqueous gel is placed into a subterraneanformation that is relatively cool as compared to the surface mixing,such as when placed below the mud line in offshore operations. Thesecondary initiator may be any suitable water-soluble compound orcompounds that may react with the primary initiator to provide freeradicals at a lower temperature. An example of a suitable secondaryinitiator is triethanolamine. In some embodiments of the presentinvention, the secondary initiator is present in the polymerizableorganic monomer composition in an amount in the range of from about 0.1%to about 5% by weight of the water-soluble polymerizable organicmonomer(s).

Also optionally, the polymerizable organic monomer compositions of thepresent invention further may comprise a crosslinking agent forcrosslinking the polymerizable organic monomer compositions in thedesired gelled substance. In some embodiments, the crosslinking agent isa molecule or complex containing a reactive transition metal cation. Amost preferred crosslinking agent comprises trivalent chromium cationscomplexed or bonded to anions, atomic oxygen, or water. Examples ofsuitable crosslinking agents include, but are not limited to, compoundsor complexes containing chromic acetate and/or chromic chloride. Othersuitable transition metal cations include chromium VI within a redoxsystem, aluminum III, iron II, iron III, and zirconium IV. Generally,the crosslinking agent may be present in polymerizable organic monomercompositions in an amount in the range of from 0.01% to about 5% byweight of the polymerizable organic monomer composition.

The method according to the invention can be advantageously employed foran open-hole wellbore, especially but not necessarily in the case of aweakly consolidated or unconsolidated formation. The method according toclaim 1, wherein the wellbore is a cased or lined wellbore.

The method can include the step of drilling the wellbore to penetratethe formation, whereby the wellbore is an open-hole wellbore. Afterdrilling the open-hole wellbore, the method can further comprise thestep of installing a casing or liner in the open-hole wellbore to form acased or lined wellbore. If a pre-existing open-hole wellbore is notalready cased or lined, the method can include the step of installing acasing or liner in the wellbore to form a cased or lined wellbore.

The details of the method according to the present invention will now bedescribed with reference to the accompanying drawings. First, a wellbore10 is drilled into the subterranean formation of interest 12 usingconventional (or future) drilling techniques. Next, depending upon thenature of the formation, the wellbore 10 is either left open hole, asshown in FIG. 1A, or lined with a casing string or slotted liner, asshown in FIG. 1B. The wellbore 10 may be left as an uncased open holeif, for example, the subterranean formation is highly consolidated or inthe case where the well is a highly deviated or horizontal well, whichare often difficult to line with casing. In cases where the wellbore 10is lined with a casing string, the casing string may or may not becemented to the formation. The casing in FIG. 1B is shown cemented tothe subterranean formation. Furthermore, when uncemented, the casingliner may be either a slotted or preperforated liner or a solid liner.Those of ordinary skill in the art will appreciate the circumstanceswhen the wellbore 10 should or should not be cased, whether such casingshould or should not be cemented, and whether the casing string shouldbe slotted, preperforated or solid. Indeed, the present invention doesnot lie in the performance of the steps of drilling the wellbore 10 orwhether or not to case the wellbore, or if so, how. The method accordingto the invention can also be applied to an older well bore that haszones that are in need of stimulation.

Once the wellbore 10 is drilled, and if deemed necessary cased, ajetting tool 14, such as that used in the SURGIFRAC process described inU.S. Pat. No. 5,765,642, is placed into the wellbore 10 at a location ofinterest, e.g., adjacent to a first zone 16 in the subterraneanformation 12. In one exemplary embodiment, the jetting tool 14 isattached to a tubing or coiled tubing 18, which lowers the jetting tool14 into the wellbore 10 and supplies it with jetting fluid. Annulus 19is formed between the tubing 18 and the wellbore 10. The jetting tool 14then operates to form perforation tunnels 20 in the first zone 16, asshown in FIG. 1. The perforation fluid being pumped through the jettingtool 14 contains a base fluid, which is commonly water and abrasives(commonly sand). As shown in FIG. 2, four equally spaced jets (in thisexample) of fluid 22 are injected into the first zone 16 of thesubterranean formation 12. As those of ordinary skill in the art willrecognize, the jetting tool 14 can have any number of jets, configuredin a variety of combinations along and around the tool.

In the next step of the well completion method according to the presentinvention, the first zone 16 is fractured. This may be accomplished byany one of a number of ways. In one exemplary embodiment, the jettingtool 14 injects a high pressure fracture fluid into the perforationtunnels 20. As those of ordinary skill in the art will appreciate, thepressure of the fracture fluid exiting the jetting tool 14 is sufficientto fracture the formation in the first zone 16. Using this technique,the jetted fluid forms cracks or fractures 24 along the perforationtunnels 20, as shown in FIG. 3. In a subsequent step, an acidizing fluidmay be injected into the formation through the jetting tool 14. Theacidizing fluid etches the formation along the cracks 24 therebywidening them.

In another exemplary embodiment, the jetted fluid carries a proppantinto the cracks or fractures 24. The injection of additional fluidextends the fractures 24 and the proppant prevents them from closing upat a later time. The present invention contemplates that otherfracturing methods may be employed. For example, the perforation tunnels20 can be fractured by pumping a hydraulic fracture fluid into them fromthe surface through annulus 19. Next, either and acidizing fluid or aproppant fluid can be injected into the perforation tunnels 20, so as tofurther extend and widen them. Other fracturing techniques can be usedto fracture the first zone 16.

FIGS. 4A-B illustrate the details of an example of a jetting tool 14 foruse in carrying out the methods of the present invention. Jetting tool14 comprises a main body 40, which is cylindrical in shape and formed ofa ferrous metal. The main body 40 has a top end 42 and a bottom end 44.The top end 42 connects to tubing or coiled tubing 18 for operationwithin the wellbore 10. The main body 40 has a plurality of nozzles 46,which are adapted to direct the high pressure fluid out of the main body40. The nozzles 46 can be disposed, and in one certain embodiment aredisposed, at an angle to the main body 40, so as to eject thepressurized fluid out of the main body 40 at an angle other than 90degrees. In other words, the fluid jet forming nozzle can be dispose atan angle other than 90° to the axis of the cylindrical main body.

The jetting tool 14 further comprises means 48 for opening the jettingtool 14 to fluid flow from the wellbore 10. Such fluid opening means 48includes a fluid-permeable plate 50, which is mounted to the insidesurface of the main body 40. The fluid-permeable plate 50 traps a ball52, which sits in seat 54 when the pressurized fluid is being ejectedfrom the nozzles 46, as shown in FIG. 4A. When the pressurized fluid isnot being pumped down the coil tubing into the jetting tool 14, thewellbore fluid is able to be circulated up to the surface via openingmeans 48. More specifically, the wellbore fluid lifts the ball 52 upagainst fluid-permeable plate 50, which in turn allows the wellborefluid to flow up the jetting tool 14 and ultimately up through thetubing 18 to the surface, as shown in FIG. 4B. As those of ordinaryskill in the art will recognize other valves can be used in place of theball and seat arrangement 52 and 54 shown in FIGS. 4A and 4B. Darts,poppets, and flappers. Furthermore, although FIGS. 4A and 4B only show avalve at the bottom of the jetting tool 14, such valves can be placedboth at the top and the bottom, as desired.

It is to be understood, of course, that other types or variations ofjetting tools can be used, for example, the jetting tools as describedin each of U.S. Pat. Nos. 5,249,628; 5,361,856; and 5,765,642, each ofwhich is incorporated by reference in its entirety.

Preferably, the step of positioning a jetting tool further comprisesaccessing the wellbore with coiled tubing.

The method preferably includes the step of isolating an interval of thewellbore in the subterranean formation, wherein the step of positioninga jetting tool further comprises positioning the jetting tool in theisolated interval. This allows the method to be selectively performed ina desired interval of the wellbore without affecting one or more otherintervals of the wellbore.

The step of isolating an interval of the wellbore preferably includesusing at least one well tool to close at least one end of the interval.The well tool for isolating an end of the interval is preferably adrillable well tool, although a removable well tool can be used. When adrillable well tool is used, the method preferably further comprises thestep of further comprising the step of drilling out the drillable welltool to reopen the wellbore. The well tool for isolating an end of theinterval can be, for example, a packer or bridge plug. The step ofisolating the interval can also be performed dynamically, e.g. using theSurgiFrac technique to isolate the section by means of fluid velocity asexplained in U.S. Pat. No. 5,765,642, which is incorporated by referenceherein in its entirety.

The step of isolating an interval of the wellbore can employ using anisolation fluid to close at least one end of the interval. When anisolation fluid is used, the method preferably further comprises thestep of removing the isolation fluid to reopen the wellbore.

For example, once the first zone 16 has been fractured, the presentinvention provides for isolating the first zone 16, so that subsequentwell operations, such as the fracturing of additional zones, can becarried out without the loss of significant amounts of fluid. Thisisolation step can be carried out in a number of ways. In one exemplaryembodiment, the isolation step is carried out by injecting into thewellbore 10 an isolation fluid, which may have a higher viscosity thanthe completion fluid already in the fracture or the wellbore.

In another exemplary embodiment, the isolation fluid is formed of afluid having a similar chemical makeup as the fluid resident in thewellbore during the fracturing operation. The fluid may have a greaterviscosity than such fluid, however. In one exemplary embodiment, thewellbore fluid is mixed with a solid material to form the isolationfluid. The solid material may include natural and man-made proppantagents, such as silica, ceramics, and bauxites, or any such materialthat has an external coating of any type. Alternatively, the solid (orsemi-solid) material may include paraffin, encapsulated acid or otherchemical, or resin beads.

In another exemplary embodiment, the isolation fluid is formed of ahighly viscous material, such as a gel or cross-linked gel. Examples ofgels that can be used as the isolation fluid include, but are notlimited to, fluids with high concentration of gels such as Xanthan.Examples of cross-linked gels that can be used as the isolation fluidinclude, but are not limited to, high concentration gels such asHalliburton's DELTA FRAC fluids or K-MAX fluids. “Heavy crosslinkedgels” could also be used by mixing the crosslinked gels with delayedchemical breakers, encapsulated chemical breakers, which will laterreduce the viscosity, or with a material such as PLA (poly-lactic acid)beads, which although being a solid material, with time decomposes intoacid, which will liquefy the K-MAX fluids or other crosslinked gels.

According to one aspect of the invention, the step of delivering acurable composition through the jetting tool and to the formationpreferably further comprises filling the wellbore interval undersufficient pressure to force the curable composition into the formation.In this embodiment, the curable composition is delivered at a relativelyslow rate through the jetting tool to merely fill the intervalsurrounding the jetting tool and form a bullhead. For example, thedelivery rate would typically be less than about 2 barrels per minute.

According to another aspect of the invention, the step of delivering acurable composition through the jetting tool and to the formationfurther comprises delivering the curable composition through the jettingtool under conditions sufficient to direct and pressure the curablecomposition into the formation. In this embodiment, the curablecomposition is delivered through the jetting tool at a sufficient ratethat may form a jet. Preferably, however, the step of delivering acurable composition through the jetting tool and to the formationfurther comprises delivering the curable composition into the formationunder conditions that are not sufficient to initiate a fracture in theformation. If desired, however, the curable composition can be injectedthrough the jetting tool under sufficient conditions to form a jet andfracture the formation.

According to yet another aspect of the invention, the method furthercomprises the step of injecting a fracturing fluid through the jettingtool under conditions sufficient to erode a portion of the wall of thewell bore and to initiate at least one fracture extending into theformation. The method can further comprise the step of moving thejetting tool axially and/or rotationally during the step of injecting afracturing fluid through the jetting tool to initiate at least onefracture so as to thereby erode a straight or helical slot in a portionof the wall of the well bore.

Preferably, the step of injecting a fracturing fluid through the jettingtool to initiate at least one fracture is separate from the step ofdelivering a curable composition through the jetting tool and to theformation, and wherein the fracturing fluid is different than thecurable composition. Preferably, the method includes performing the stepof injecting a fracturing fluid through the jetting tool to initiate atleast one fracture before performing the step of delivering a curablecomposition through the jetting tool and to the formation.

During at least part of the step of injecting a fracturing fluid throughthe jetting tool, the fracturing fluid preferably comprises a base fluidand a particulate material. Preferably, the viscosity of the curablecomposition is less than the viscosity of the base fluid. Whereas thecurable composition preferably has a relatively low viscosity to allowit to move more easily into the formation rock, i.e., into and throughthe porosity of the formation, the base fluid of a fracturing fluidpreferably has a relatively high viscosity to help suspend and carry theproppant into a fracture without prematurely settling out of the fluid.For example, the base fluid can be a gelled fluid and the particulatecan be sand. A typical base fluid has an apparent viscosity of greatthan about 2,000 centipoise.

The method preferably further comprises the step of injecting afracturing fluid down the annulus under conditions to sufficiently raisethe fluid pressure in the annulus to extend the at least one fractureinitiated by the step of injecting a fracturing fluid through thejetting tool. During at least part of the step of injecting a fracturingfluid down the annulus, the fracturing fluid preferably comprises a basefluid and a particulate material. The base fluid has high viscosity tohelp suspend and carry the proppant into a fracture without prematurelysettling out of the fluid.

Preferably, the proppant is coated with a curable composition.Preferably, the curable composition that is used for this step ofdepositing a proppant coated with a curable composition into thefracture in the formation is a hardenable resin composition. If desired,and as may be preferably in certain formations containing fines,however, the proppant can be coated with a tackifying composition. It isto be understood that if desired, a portion of the proppant used in themethods according to the invention can be coated with a hardenable resincomposition and another portion of the proppant can be coated with atackifying composition.

When a hardenable resin composition is used to coat the proppant, themethod of the invention preferably further comprises the step ofallowing or causing the hardenable resin composition to harden beforeperforming the step of flowing back or producing fluid from theformation. For a self-hardening resin composition, the time required forhardening will depend on the temperature of the formation. Otherhardenable resin compositions may require an overflush with a fluidcontaining an appropriate catalyst to cause the hardenable resincomposition to harden.

The curable composition that is used for the step of depositing aproppant coated with a curable composition into the fracture in theformation should have a sufficiently high viscosity to form a coating onthe proppant.

In the case of practicing the method in a cased or lined wellbore, themethod can further comprise the step of perforating the casing orlining. Preferably, the jetting tool is used to perforate the casing orliner. For example, for a cased or lined wellbore, the method preferablyfurther comprises the step of injecting a perforating fluid through thejetting tool under conditions sufficient to erode a portion of the wallof the casing or liner to form at least one perforation in the cased orlined wellbore before the step of delivering a curable compositionthrough the jetting tool and to the formation. In such a case, themethod preferably further comprises the step of injecting a fracturingfluid through the jetting tool and through the perforation underconditions sufficient to erode the wall of the well bore outside thecasing or liner and to initiate at least one fracture in the formation.Although these steps can be practiced at the same time, the step ofinjecting a perforating fluid can be separate from the step of injectinga fracturing fluid, and the perforating fluid is not necessarily thesame as the fracturing fluid.

The method according to the invention can optionally further comprisethe step of overflushing the curable composition in the formation withan overflush fluid capable of displacing at least some of the curablecomposition farther out into the formation. This is particularlyadvantageous where it is desired to modify the permeability of theconsolidated formation relative to that which would be obtained withoutthe overflush. The overflush fluid is preferably an aqueous solution.The step of overflushing the curable composition further comprises:delivering the overflush fluid through the jetting tool and to theformation under conditions that are not sufficient to initiate afracture in the formation. There may be some overlap in the introductionof overflush fluid and the curable composition, for example, in caseswhere separate pumping devices are used.

Preferably, the overflush fluid is placed into the formation at a matrixflow rate such that the low-viscosity resin is displaced from thechannels, but is not displaced from its desired location between theformation sand particles. Generally, the volume of after-flush fluidplaced in the subterranean formation ranges from about 0.1 to about 50times the volume of the low-viscosity curable composition. In someembodiments of the present invention, the volume of overflush fluidplaced in the subterranean formation ranges from about 2 to about 5times the volume of the low-viscosity curable composition.

The method according to the invention preferably further comprise thestep of flowing back or producing fluid from the formation. The methodpreferably further comprises the step of allowing or causing the curablecomposition to cure before performing the step of flowing back orproducing fluid from the formation.

It is to be understood that the various steps according to preferredmethods of the invention can be advantageously practiced in variouscombinations. It is also to be understood that the steps according tothe invention and various preferred embodiments of the invention can berepeated at different intervals of the same wellbore.

EXAMPLES

An example of the steps of a method according to the invention include:for a wellbore penetrating a weakly consolidated or unconsolidatedformation, isolating an interval of a wellbore from at least one otherinterval, for example, with at least one removable or drillable packeror with a removable or drillable bridge plug; accessing the isolatedinterval with tubing, preferably with coiled tubing, to position ajetting tool in the isolated interval; delivering a hardenable resincomposition through the jetting tool while filling the wellbore intervaland forming a bullhead of the hardenable resin composition; optionallyallowing or causing the hardenable resin composition to harden to form aconsolidated mass; injecting a fracturing fluid through the jetting toolunder conditions sufficient to form at least one slot and to initiate afracture in the formation; depositing a proppant coated with ahardenable resin composition in the generated fracture; optionallyallowing or causing the coated proppant to harden into a consolidatedmass; removing or drilling out the packer or bridge plug; and producinghydrocarbon from the formation.

Another, more preferred example of the steps of a method according tothe invention include: for a wellbore penetrating a weakly consolidatedor unconsolidated formation, isolating an interval of a wellbore from atleast one other interval, for example, with at least one removable ordrillable packer or with a removable or drillable bridge plug; accessingthe isolated interval with tubing, preferably with coiled tubing, toposition a jetting tool in the isolated interval; injecting a fracturingfluid through the jetting tool under conditions sufficient to form atleast one slot and to initiate a fracture in the formation; depositing aproppant into the fracture; delivering a hardenable resin compositionthrough the jetting tool while filling the wellbore interval and forminga bullhead of the hardenable resin composition; optionally allowing orcausing the hardenable resin composition to harden to form aconsolidated mass; removing or drilling out the packer or bridge plug;and producing hydrocarbon from the formation.

Thus, the present invention is well adapted to carry out the objects andattain the ends and advantages mentioned above as well as those inherenttherein. While preferred embodiments of the invention have beendescribed for the purpose of this disclosure, changes in theconstruction and arrangement of parts and the performance of steps canbe made by those skilled in the art, which changes are encompassedwithin the spirit of this invention as defined by the appended claims.

1. A method of treating a subterranean formation, the method comprisingthe steps of: a. positioning a jetting tool in a wellbore penetratingthe subterranean formation, wherein the jetting tool comprises at leastone fluid jet forming nozzle; and b. delivering a curable compositionthrough the jetting tool and to the formation, wherein i. at least acomponent of the curable composition is capable of curing to form asolid substance or a semi-solid, gel-like substance, and ii. the curablecomposition is a fluid having a sufficiently low viscosity to penetrateinto the formation.
 2. The method according to claim 1, wherein theviscosity is sufficiently low that no substantial amount of residueremains behind filling the pore spaces of the formation as the curablecomposition penetrates into the formation.
 3. The method according toclaim 1, wherein the apparent viscosity of the curable composition ispreferably below about 100 cP.
 4. The method according to claim 3,wherein the apparent viscosity of the curable composition is measuredwithin the range of the bottom hole static temperature of thesubterranean formation.
 5. The method according to claim 4, wherein theapparent viscosity of the curable composition is measured at the lowerlimit of the bottom hole static temperature of the subterraneanformation.
 6. The method according to claim 1, wherein the curablecomposition is a hardenable resin composition.
 7. The method accordingto claim 1, further comprising the step of: isolating an interval of thewellbore in the subterranean formation, wherein the step of positioninga jetting tool further comprises positioning the jetting tool in theisolated interval.
 8. The method according to claim 1, wherein the stepof delivering a curable composition through the jetting tool and to theformation further comprises: filling the wellbore interval undersufficient pressure to force the curable composition into the formation.9. The method according to claim 1, wherein the step of delivering acurable composition through the jetting tool and to the formationfurther comprises: delivering the curable composition through thejetting tool under conditions sufficient to direct and pressure thecurable composition into the formation.
 10. The method according toclaim 8, wherein the step of delivering a curable composition throughthe jetting tool and to the formation further comprises: delivering thecurable composition into the formation under conditions that are notsufficient to initiate a fracture in the formation.
 11. The methodaccording to claim 1, further comprising the step of: injecting afracturing fluid through the jetting tool under conditions sufficient toerode a portion of the wall of the well bore and to initiate at leastone fracture extending into the formation.
 12. The method according toclaim 11, wherein the step of injecting a fracturing fluid through thejetting tool to initiate at least one fracture is separate from the stepof delivering a curable composition through the jetting tool and to theformation, and wherein the fracturing fluid is different than thecurable composition.
 13. The method according to claim 12, comprisingperforming the step of injecting a fracturing fluid through the jettingtool to initiate at least one fracture before performing the step ofdelivering a curable composition through the jetting tool and to theformation.
 14. The method according to claim 11, wherein during at leastpart of the step of injecting a fracturing fluid through the jettingtool, the fracturing fluid comprises a base fluid and a particulatematerial.
 15. The method according to claim 14, wherein the viscosity ofthe curable composition is less than the viscosity of the base fluid.16. The method according to claim 14, wherein the particulate materialis coated with a curable composition.
 17. The method according to claim16, wherein the curable composition that is used for the step ofdepositing a proppant coated with a curable composition into thefracture in the formation has a sufficiently high viscosity to form acoating on the proppant.
 18. The method according to claim 1, furthercomprising the step of: flowing back or producing fluid from theformation.
 19. A method of treating a subterranean formation, the methodcomprising the steps of: a. isolating an interval of the wellborepenetrating the subterranean formation; b. positioning a jetting tool inthe isolated interval of the subterranean formation, wherein the jettingtool comprises at least one fluid jet forming nozzle; c. injecting afracturing fluid through the jetting tool under conditions sufficient toerode a portion of the wall of the well bore and to initiate at leastone fracture extending into the formation; and d. delivering a curablecomposition through the jetting tool and to the formation, wherein i. atleast a component of the curable composition is capable of curing toform a solid substance or a semi-solid, gel-like substance, and ii. thecurable composition is a fluid having a sufficiently low viscosity topenetrate into the formation.
 20. A method of treating a subterraneanformation, wherein the formation is weakly consolidated orunconsolidated, the method comprising the steps of: a. positioning ajetting tool a wellbore penetrating the subterranean formation, whereinthe jetting tool comprises at least one fluid jet forming nozzle; b.injecting a fracturing fluid through the jetting tool under conditionssufficient to erode a portion of the wall of the well bore and toinitiate at least one fracture extending into the formation; and c.delivering a curable composition through the jetting tool and to theformation, wherein i. at least a component of the curable composition iscapable of curing to form a solid substance or a semi-solid, gel-likesubstance, and ii. the curable composition is a fluid having asufficiently low viscosity to penetrate into the formation.